The Elk Creek Carbonatite,Southeast Nebraska–An Overview

A framework geophysical program in southeastern Nebraska during 1970 identified a near-circular feature having gravity relief of about 8 mgal and a magnetic anomaly of about 800 gammas. Analysis of the geophysical data provided a model of a cylindrical mass of indefinite length with a radius of 5500 ft (1676 m) and beveled at the basement surface at about 600 ft (183 m). At the approximate depth at which Precambrian rocks were expected, the initial test hole (2-B-71) encountered an iron-rich weathered zone overlying carbonate-rich rock. The carbonate rocks consist essentially of dolomite, calcite, and ankerite and lesser amounts of hematite, chlorite, phlogopite, barite, serpentine, pyrochlore, and quartz and contain barium, strontium, and rare earths. Total REE, P2O5, and 87Sr/86Sr ratios confirm the carbonatite identification. Texturally, the rocks range from fragmental to contorted to massive. Associated with the carbonatite are lesser amounts of basalt, lamprophyre, and syenite. Additional exploratory drilling has provided about 80,000 ft (24,384 m) of rock record and has penetrated about 3400 ft (1038 m) of carbonatite. The carbonatite is overlain by marine sediments of Pennsylvanian (Missourian) age. The surrounding Precambrian basement rocks are low-to medium-grade metamorphic gneiss and schist of island arc origin and granitic plutons. The Elk Creek carbonatite is located near the boundary between the Penokean orogen created at about 1.84 Ga (billion years) and the Dawes terrane (1.78 Ga) of the Central Plains orogen. This boundary strongly influenced the geometry of both the Midcontinent Rift System (1.1 Ga) and the Nemaha uplift (0.3 Ga). It is assumed that the emplacement of the Elk Creek carbonatite (0.5 Ga) was influenced similarly by the pre-existing tectonic sutures.     

A Petroleum System for the Salina Basin in Kansas Based on Organic Geochemistry and Geologic Analog

The Salina Basin historically has been an exploration desert—a home of dryholes. Although this basin, which underlies much of north-central Kansas, may never be a prolific source of hydrocarbons, recent research into the maturation and geochemistry of organic matter and oils in Kansas can provide guidelines for a new exploration strategy. The Salina Basin is similar to the oil-productive Forest City Basin in northeastern Kansas in many ways. Both basins originated as a single large basin (i.e., the North Kansas Basin) prior to the rise of the Nemaha Uplift in Late Mississippian-Early Pennsylvanian time. Their Paleozoic stratigraphy thus is similar and the axes of both basins are presently at approximately the same depth. Thermal maturation modeling and available organic-matter maturation data indicate that the lower Paleozoic rocks in the axes of both basins are in the early stages of oil generation. In the Forest City Basin the Ordovician Simpson Group is the deepest known hydrocarbon source-rock—oil-reservoir interval, and by analogy, exploration tests in the Salina Basin, at a minimum, should penetrate through this stratigraphic interval. Ordovician Simpson Group shales in the Forest City Basin are the source rocks for a geochemically distinct oil, which also occurs in Ordovician reservoirs in the extreme southern end of the Salina Basin. To increase the odds of success in an exploration program in the Salina Basin, wildcat wells should be drilled where thermal maturation is greatest. The broad NW–SE-trending basin axis is the most logical area. Exploration tests along this axis in the northern end of the basin may have an extra advantage as organic matter in the Simpson Group may be more thermally mature because of greater burial depth during the Cretaceous. Along the eastern margin of the nearby Central Kansas Uplift and Pratt Anticline, several Paleozoic geologic structures, some of which contain major oil fields, are attributable to tectonic reactivation along the western margin of the Precambrian Central North American Rift System (CNARS). Prospective structural trends in the Paleozoic section of the Salina Basin are anticipated to be associated with this underlying tectonic boundary. The western margin of the CNARS trends NNE–SSW where it passes under the axis of the Salina Basin in northeastern Lincoln and southeastern Mitchell counties. This area is sparsely drilled, with less than two tests per township. If an exploration program can define lower Paleozoic structural closures in this region, these structures may represent the best chance for future petroleum discoveries.     

Deep Natural Gas Resources

From a geological perspective, deep natural gas resources generally are defined as occurring in reservoirs below 15,000 feet, whereas ultradeep gas occurs below 25,000 feet. From an operational point of view, deep may be thought of in a relative sense based on the geologic and engineering knowledge of gas (and oil) resources in a particular area. Deep gas occurs in either conventionally trapped or unconventional (continuous-type) basin-center accumulations that are essentially large single fields having spatial dimensions often exceeding those of conventional fields.Exploration for deep conventional and continuous-type basin-center natural gas resources deserves special attention because these resources are widespread and occur in diverse geologic environments. In 1995, the U.S. Geological Survey estimated that 939 TCF of technically recoverable natural gas remained to be discovered or was part of reserve appreciation from known fields in the onshore areas and state waters of the United States. Of this USGS resource, nearly 114 trillion cubic feet (Tcf) of technically recoverable gas remains to be discovered from deep sedimentary basins. Worldwide estimates of deep gas also are high. The U.S. Geological Survey World Petroleum Assessment 2000 Project recently estimated a world undiscovered conventional gas resource outside the U.S. of 844 Tcf below 4.5 km (about 15,000 feet).Less is known about the origins of deep gas than about the origins of gas at shallower depths because fewer wells have been drilled into the deeper portions of many basins. Some of the many factors contributing to the origin and accumulation of deep gas include the initial concentration of organic matter, the thermal stability of methane, the role of minerals, water, and nonhydrocarbon gases in natural gas generation, porosity loss with increasing depth and thermal maturity, the kinetics of deep gas generation, thermal cracking of oil to gas, and source rock potential based on thermal maturity and kerogen type. Recent experimental simulations using laboratory pyrolysis methods have provided much information on the origins of deep gas.Technologic problems are among the greatest challenges to deep drilling. Problems associated with overcoming hostile drilling environments (e.g. high temperatures and pressures, and acid gases such as CO₂ and H₂S) for successful well completion, present the greatest obstacles to drilling, evaluating, and developing deep gas fields. Even though the overall success ratio for deep wells (producing below 15,000 feet) is about 25%, a lack of geological and geophysical information continues to be a major barrier to deep gas exploration.Results of recent finding-cost studies by depth interval for the onshore U.S. indicate that, on average, deep wells cost nearly 10 times more to drill than shallow wells, but well costs and gas recoveries differ widely among different gas plays in different basins.Based on an analysis of natural gas assessments, deep gas holds significant promise for future exploration and development. Both basin-center and conventional gas plays could contain significant deep undiscovered technically recoverable gas resources.     

Evaluation of Upper Triassic T3x5 Source Rocks (Western Sichuan Depression, Sichuan Basin) and their Hydrocarbon Generation and Expulsion Characteristics: Implication for Tight-Sand Gas and Shale Gas Accumulation Potential Assessment

An unconventional, continuous petroleum system consists of an accumulation of hydrocarbons that is found in low-matrix-permeability rocks and contain large amounts of hydrocarbons. Tight-sand gas in the Jurassic and shale gas within the fifth member of Xujiahe Formation (T₃x⁵) are currently regarded as the most prolific emerging unconventional gas plays in China. The conventional and systematical evaluation of T₃x⁵ source rocks was carried out for the first time in the western Sichuan basin (WSD). Hydrocarbon generation and expulsion characteristics (including intensity, efficiency, and amount) of T₃x⁵ source rocks were investigated. Results show that T₃x⁵ source rocks are thick (generally >200 m), have high total organic content (TOC, ranging from 2.5 to 4.5 wt%), and dominated by III-type kerogen. These favorable characteristics result in a great hydrocarbon generating potential under the high thermal evolution history (R _o > 1.2%) of the area. An improved hydrocarbon generation potential methodology was applied to well data from the area to unravel the hydrocarbon generation and expulsion characteristics of T₃x⁵ source rocks in the WSD. Results indicate that the source rocks reached hydrocarbon expulsion threshold at 1.06% R _o and the comprehensive hydrocarbon expulsion efficiency was about 60%. The amount of generation and expulsion from T₃x⁵ source rocks was 3.14 × 10¹⁰ and 1.86 × 10¹⁰ t, respectively, with a residual amount of 1.28 × 10¹⁰ t within the source rocks. Continuous-type tight-sand gas was predicted to develop in the Jurassic in the Chengdu Sag of the WSD because of the good source-reservoir configuration (i.e., the hydrocarbon generation and expulsion center was located in Chengdu Sag), the Jurassic sandstone reservoirs were tight, and the gas expelled from the T₃x⁵ source rocks migrated for very short distances vertically and horizontally. The amount of gas accumulation in the Jurassic reservoirs derived from T₃x⁵ source rocks is up to 9.3 × 10⁸ t. The T₃x⁵ gas shale has good accumulation potential compared with several active US shale-gas plays. Volumetrically, the geological resource of shale gas is up to 1.05 × 10¹⁰ t. Small differences between the amounts calculated by volumetric method compared with that by hydrocarbon generation potential methodology may be due to other gas accumulations present within interbedded sands associated with the gas shales.     

The Geology and Petroleum Resources of Kansas: A Review From Alpha to Omega or From the Pleistocene to the Precambrian

The geological story of Kansas is told through the rocks that are present. It is a simple story in generalities but complex in detail. Knowing the story, gives insight into understanding the occurrence and location of possible economic valuable minerals, such as petroleum. This is a brief review of Kansas geology with respect to the known occurrence of oil and gas. Kansas is part of the Midcontinent oil province with oil having been discovered 150 years ago and commercial production commencing in 1873. Although many prospects remain in Kansas, the state has gone from the number 1 producer in the U.S. in 1916 to 8th today. Exploration for new oil and gas production therefore is going to have to be more imaginative and utilize new approaches and techniques to find the elusive petroleum. There are possibilities however for the prospector who can search diligently. Although the big fields probably have been discovered, the prospects today are deeper, in more undetectable traps, and in essentially untested places.     

Kansas Energy Sources: A Geological Review

Kansas produces both conventional energy (oil, gas, and coal) and nonconventional (coalbed gas, wind, hydropower, nuclear, geothermal, solar, and biofuels) and ranks the 22nd in state energy production in the U.S. Nonrenewable conventional petroleum is the most important energy source with nonrenewable, nonconventional coalbed methane gas becoming increasingly important. Many stratigraphic units produce oil and/or gas somewhere in the state with the exception of the Salina Basin in north-central Kansas. Coalbed methane is produced from shallow wells drilled into the thin coal units in southeastern Kansas. At present, only two surface coal mines are active in southeastern Kansas. Although Kansas has been a major exporter of energy in the past (it ranked first in oil production in 1916), now, it is an energy importer.     

Distinction Between Oil Expulsion History and Gas Expulsion History

The process of organic matter transformation into oil and gas is also a balance process of hydrocarbon transformation. This article probes to distinguish the oil expulsion history from gas expulsion history based on the hydrocarbon generation, hydrocarbon residual, and hydrocarbon expulsion processes of the source rocks. In this method, the first step is to study the hydrocarbon expulsion rate by means of hydrocarbon generation potential method; the second step is to study the oil generation rate by means of the heating–pressuring experiment method; the third step is to study the oil residual rate by means of the mathematical method. The difference between the values of oil generation rate and oil residual rate is defined as the oil expulsion rate, while that between the values of hydrocarbon expulsion rate and the gas expulsion rate is defined as the gas expulsion rate. Then, combined with the geological parameters of source rocks, the oil and gas expulsion history can be obtained. This study on Es₁ Source rocks, Nanpu Sag, Bohai Bay Basin, China shows that the primary expulsion period of Es₁ source rocks is Guantao–Minghuazhen period.     

Interpretation of a gas chimney in the Polish Carpathian Foredeep based on integrated seismic and geochemical data

Gas chimneys are common in offshore petroliferous basins, but little known on land where seismic columnar anomalies are often attributed as poor data quality or processing artefacts. This study utilizes high‐quality 3D seismic data to document a seismic columnar anomaly penetrating through the Miocene heterolithic submarine fan‐deltaic infill of the Carpathian Foredeep. The interpreted gas chimney exhibits vertically clustered velocity push‐down features throughout the attenuated amplitude column accompanied by gas shows in well tests, has its root in gas‐bearing Palaeozoic interval and culminates in an anomalous geochemical gas record at soil level. The chimney system, ca 2 km in height and 500‐m wide, begins above the flank of a rotational bedrock fault‐block and extends vertically along a fault‐controlled conduit. At shallower levels, it passes upwards into amplitude wipeout zones that spread laterally around and partly across thin, gas‐charged reservoirs showing bright spots associated with an AVO response. At shallow levels, gas pathways through muddy slope and deltaic clinoforms are not imaged in low‐fold regions of the seismic volume. The surface geochemical anomalies, in contrast to the microbial methane signature of the Miocene succession, show significant enrichment in higher alkanes and alkenes with C₂H₆/C₃H₈ ratios indicative of a deep‐sourced, thermogenic gas or gas condensate. These anomalies form a semi‐enclosed halo around the chimney. Despite the juxtaposition of biogenic and thermogenic methane, the chimney structure imaged on seismic data supports a causal link of gases derived from Palaeozoic source rocks ascending to the surface.     

Improved Minimum Miscibility Pressure Prediction for Gas Injection Process in Petroleum Reservoir

Determination of gas–oil minimum miscibility conditions is one of the important design parameters to improve the displacement efficiency of the hydrocarbon reservoir during enhanced oil recovery with gas injection. In this work, a support vector regression (SVR) model is developed using experimental data to estimate the minimum miscibility pressure (MMP) for various reservoir fluids and injection gases. Experimental MMP data taken from the reliable literature were used as input. Each data point input includes methane and intermediate components mole percent, plus fraction properties and reservoir temperature related to reservoir fluid and CO₂, H₂S, N₂ and intermediate mole fractions, and intermediate properties of the injected gas. Experimental MMP is regarded as the model output. The database contains 135 datasets, from which 125 datasets were used for model development, and the rest were used for model evaluation. Genetic algorithm was implemented to optimize the SVR model parameters. The proposed data-driven model was verified by statistical validation data. The model results illustrate a correlation coefficient (R²) of 0.999. In addition, the SVR results demonstrate the proposed model to be a fast tool and a robust approach to map input space to output features. The SVR model was compared to popular data-driven MMP estimation models as well. This comparison presents an acceptable accuracy relative to this estimation model. Finally, the presented model was evaluated against a comprehensive theoretical model of slim tube compositional simulation on a trusted literature dataset.     

Relevance of Pentane- and Hexane-Utilizing Bacterial Indicators for Finding Hydrocarbon Microseepage: A Study from Jamnagar Sub-basin, Saurashtra, Gujarat, India

Mesozoic sediments are source rocks for nearly half the world’s hydrocarbon reserves. Hence, there is great interest in the oil industry to know the trap and sub-trappean sediment thickness and their extent in the trap covered regions of Jamnagar study area. The microbial prospecting method is applied in the Jamnagar sub-basin, Gujarat for evaluating the prospects for hydrocarbon exploration by investigating the anomalous abundance of n-pentane- and n-hexane-oxidizing bacteria of this area. A total of 150 near-surface soil samples were collected in Jamnagar sub-basin, Gujarat for the evaluation of hydrocarbon resource potential of the basin. In this study, bacterial counts for n-pentane-utilizing bacteria range between 1.09 × 10² and 9.89 × 10⁵ cfu/g and n-hexane-utilizing bacteria range between 1.09 × 10² and 9.29 × 10⁵ cfu/g. The adsorbed hydrocarbon gases consisting of ethane plus hydrocarbons (ΣC₂₊) of 1–977 ppb and n-pentane (nC₅) of 1–23 ppb. The integrated geomicrobial and adsorbed soil gas studies showed the anomalous hydrocarbon zones nearby Khandera, Haripur, and Laloi areas which could probably aid to assess the true potential of the basin. Integrated geophysical studies have shown that Jamnagar sub-basin of Saurashtra has significant sediment thickness below the Deccan Traps and can be considered for future hydrocarbon exploration.     

Incremental Growth of Plains-Type (Compactional) Folds in a Cratonic Environment as Revealed by the Sedimentary Sequence

The enigma of the origin and development of plains-type folds, as they were christened in the early 20th Century, essentially has been solved. The folds, a considerable distance from the tectonic disturbance, were formed by draping of sediments over differentially displaced Precambrian basement fault blocks. These Precambrian basement fault blocks controlled the location, size, and shape of the folds. Forces were transmitted through the rigid basement causing readjustment along the indigenous fracture/fault pattern formed much earlier. In the U.S. Midcontinent, the crystalline basement is overlain by a thin veneer of sediments, and once the structures were formed, they continued to develop as evidenced by features in the overlying sediments. As the stress was transmitted through the basement and then relaxed, the fault blocks moved differentially in concert to these outside forces. Sediment compaction and nondeposition over structural topographic highs reacted accordingly to form the features as seen today. To determine the structural history, structural closure on different horizons on the anticline is plotted in their appropriate stratigraphic position at depth. This gives a compaction line for each tectonically coherent segment. Similar segments show a relatively straightline with offsets at major unconformities indicating breaks in the continuum. It is at these breaks that the section can be stretched until the compaction line matches as a continuum with the resulting gap giving the approximate amount of missing section for that part of the rock column. Conversely, the amount of closure on a structure at depth for each line segment can be estimated by extrapolating downward in that segment. This technique to determine depth of burial and thus the amount of missing stratigraphic section from well data at numerous locations has been compared with estimates made by other methods and the results are similar. Where no other data are available or for quick estimates, then, it is proposed that this approach will give reasonable results and that the values can be used as a constraint in basin modeling.     

Crustal‐scale fluid flow during the tectonic evolution of the Bighorn Basin (Wyoming,USA)

Stable isotope measurements (O, C, Sr), microthermometry and salinity measurements of fluid inclusions from different fracture populations in several anticlines of the Sevier‐Laramide Bighorn basin (Wyoming, USA) were used to unravel the palaeohydrological evolution. New data on the microstructural setting were used to complement previous studies and refine the fracture sequence at basin scale. The latter provides the framework and timing of fluid migration events across the basin during the Sevier and Laramide orogenic phases. Since the Sevier tectonic loading of the foreland basin until its later involvement into the Laramide thick‐skinned orogeny, three main fracture sets (out of seven) were found to have efficiently enhanced the hydraulic permeability of the sedimentary cover rocks. These pulses of fluid are attested by calcite crystals precipitated in veins from hydrothermal (T > 120 °C) radiogenic fluids derived from Cretaceous meteoric fluids that interacted with the Precambrian basement rocks. Between these events, vein calcite precipitated from formational fluids at chemical and thermal equilibrium with surrounding environment. At basin scale, the earliest hydrothermal pulse is documented in the western part of the basin during forebulge flexuring and the second one is documented in basement‐cored folds during folding. In addition to this East/West diachronic opening of the cover rocks to hydrothermal pulses probably controlled by the tectonic style, a decrease in ^87/86Sr values from West to East suggests a crustal‐scale partially squeegee‐type eastward fluid migration in both basement and cover rocks since the early phase of the Sevier contraction. The interpretation of palaeofluid system at basin scale also implies that joints developed under an extensional stress regime are better vertical drains than joints developed under strike‐slip regime and enabled migration of basement‐derived hydrothermal fluids.     

The structural evolution of the Halten Terrace,offshore Mid‐Norway: extensional fault growth and strain localisation in a multi‐layer brittle–ductile system

Tectonic subsidence in rift basins is often characterised by an initial period of slow subsidence (‘rift initiation’) followed by a period of more rapid subsidence (‘rift climax’). Previous work shows that the transition from rift initiation to rift climax can be explained by interactions between the stress fields of growing faults. Despite the prevalence of evaporites throughout the geological record, and the likelihood that the presence of a regionally extensive evaporite layer will introduce an important, sub‐horizontal rheological heterogeneity into the upper crust, there have been few studies that document the impact of salt on the localisation of extensional strain in rift basins. Here, we use well‐calibrated three‐dimensional seismic reflection data to constrain the distribution and timing of fault activity during Early Jurassic–Earliest Cretaceous rifting in the Åsgard area, Halten Terrace, offshore Mid‐Norway. Permo‐Triassic basement rocks are overlain by a thick sequence of interbedded halite, anhydrite and mudstone. Our results show that rift initiation during the Early Jurassic was characterised by distributed deformation along blind faults within the basement, and by localised deformation along the major Smørbukk and Trestakk faults within the cover. Rift climax and the end of rifting showed continued deformation along the Smørbukk and Trestakk faults, together with initiation of new extensional faults oblique to the main basement trends. We propose that these new faults developed in response to salt movement and/or gravity sliding on the evaporite layer above the tilted basement fault blocks. Rapid strain localisation within the post‐salt cover sequence at the onset of rifting is consistent with previous experimental studies that show strain localisation is favoured by the presence of a weak viscous substrate beneath a brittle overburden.     

Cost Implications of Uncertainty in CO<Subscript>2</Subscript> Storage Resource Estimates: A Review

Carbon capture from stationary sources and geologic storage of carbon dioxide (CO₂) is an important option to include in strategies to mitigate greenhouse gas emissions. However, the potential costs of commercial-scale CO₂ storage are not well constrained, stemming from the inherent uncertainty in storage resource estimates coupled with a lack of detailed estimates of the infrastructure needed to access those resources. Storage resource estimates are highly dependent on storage efficiency values or storage coefficients, which are calculated based on ranges of uncertain geological and physical reservoir parameters. If dynamic factors (such as variability in storage efficiencies, pressure interference, and acceptable injection rates over time), reservoir pressure limitations, boundaries on migration of CO₂, consideration of closed or semi-closed saline reservoir systems, and other possible constraints on the technically accessible CO₂ storage resource (TASR) are accounted for, it is likely that only a fraction of the TASR could be available without incurring significant additional costs. Although storage resource estimates typically assume that any issues with pressure buildup due to CO₂ injection will be mitigated by reservoir pressure management, estimates of the costs of CO₂ storage generally do not include the costs of active pressure management. Production of saline waters (brines) could be essential to increasing the dynamic storage capacity of most reservoirs, but including the costs of this critical method of reservoir pressure management could increase current estimates of the costs of CO₂ storage by two times, or more. Even without considering the implications for reservoir pressure management, geologic uncertainty can significantly impact CO₂ storage capacities and costs, and contribute to uncertainty in carbon capture and storage (CCS) systems. Given the current state of available information and the scarcity of (data from) long-term commercial-scale CO₂ storage projects, decision makers may experience considerable difficulty in ascertaining the realistic potential, the likely costs, and the most beneficial pattern of deployment of CCS as an option to reduce CO₂ concentrations in the atmosphere.     

Quantitative assessment of mineral resources with an application to petroleum geology

The probability of occurrence of natural resources, such as petroleum deposits, can be assessed by a combination of multivariate statistical and geostatistical techniques. The area of study is partitioned into regions that are as homogeneous as possible internally while simultaneously as distinct as possible. Fisher's discriminant criterion is used to select geological variables that best distinguish productive from nonproductive localities, based on a sample of previously drilled exploratory wells. On the basis of these geological variables, each wildcat well is assigned to the production class (dry or producer in the two-class case) for which the Mahalanobis' distance from the observation to the class centroid is a minimum. Universal kriging is used to interpolate values of the Mahalanobis' distances to all locations not yet drilled. The probability that an undrilled locality belongs to the productive class can be found, using the kriging estimation variances to assess the probability of misclassification. Finally, Bayes' relationship can be used to determine the probability that an undrilled location will be a discovery, regardless of the production class in which it is placed. The method is illustrated with a study of oil prospects in the Lansing/Kansas City interval of western Kansas, using geological variables derived from well logs.     

Geochemical Characteristics of Oil from Oligocene Lower Ganchaigou Formation Oil Sand in Northern Qaidam Basin,China

Oil from the Oligocene oil sands of the Lower Ganchaigou Formation in the Northern Qaidam Basin and the related asphaltenes was analyzed using bulk and organic geochemical methods to assess the organic matter source input, thermal maturity, paleo-environmental conditions, kerogen type, hydrocarbon quality, and the correlation between this oil and its potential source rock in the basin. The extracted oil samples are characterized by very high contents of saturated hydrocarbons (average 62.76%), low contents of aromatic hydrocarbons (average 16.11%), and moderate amounts of nitrogen–sulfur–oxygen or resin compounds (average 21.57%), suggesting that the fluid petroleum extracted from the Oligocene oil sands is of high quality. However, a variety of biomarker parameters obtained from the hydrocarbon fractions (saturated and aromatic) indicate that the extracted oil was generated from source rocks with a wide range of thermal maturity conditions, ranging from the early to peak oil window stages, which are generally consistent with the biomarker maturity parameters, vitrinite reflectance (approximately 0.6%), and T_max values of the Middle Jurassic carbonaceous mudstones and organic-rich mudstone source rocks of the Dameigou Formation, as reported in the literature. These findings suggest that the studied oil is derived from Dameigou Formation source rocks. Furthermore, the source- and environment-related biomarker parameters of the studied oil are characterized by relatively high pristane/phytane ratios, the presence of tricyclic terpanes, low abundances of C₂₇ regular steranes, low C₂₇/C₂₉ regular sterane ratios, and very low sterane/hopane ratios. These data suggest that the oil was generated from source rocks containing plankton/land plant matter that was mainly deposited in a lacustrine environment and preserved under sub-oxic to oxic conditions, and the data also indicate a potential relationship between the studied oil and the associated potential source rocks. The distribution of pristane, phytane, tricyclic terpanes, regular steranes and hopane shows an affinity with the studied Oligocene Lower Ganchaigou Formation oil to previously published Dameigou Formation source rocks. In support of this finding, the pyrolysis–gas chromatography results of the analyzed oil asphaltene indicate that the oil was primarily derived from type II organic matter, which is also consistent with the organic matter of the Middle Jurassic source rocks. Thus, the Middle Jurassic carbonaceous mudstones and organic rock mudstones of the Dameigou Formation could be significantly contributing source rocks to the Oligocene Lower Ganchaigou Formation oil sand and other oil reservoirs in the Northern Qaidam Basin.

     

Numerical modelling of the hydrocarbon generation of Tertiary source rocks intruded by doleritic sills in the Zhanhua depression,Bohai Bay Basin,China

An igneous hydrocarbon reservoir had been found in the Zhanhua depression, Bohai Bay Basin, eastern China. Two doleritic sills successively intruded into the immature source rock of the third member of the Shahejie Formation (Es3). The heat released from the magma changed the mineral composition of wall rocks and accelerated the maturity of organic matter. Thin hornfels and carbargilite zones were found next to the sills. The vitrinite reflectances (%R_o) of these heated wall rocks increased to at least 1.4% near the contacts (<50 m), and accumulation of oil was found in the hornfels zone and dolerite bodies. With the aim of understanding the influence of the sills on the hydrocarbon generation process, a complex heat conduction model was used to simulate the thermal history of the organic‐rich wall rocks, in which both the latent heat of crystallization of intrusions and vapourization heat of pore water in wall rocks were considered. The simulation results suggested that the cooling of each sill continued for about 0.1 Ma after its emplacement and the temperature of wall rocks was considerably raised. The peak temperature (T_peak) that wall rocks experienced can reach 460–650°C in the region of 10 m away from the contacts. The thermal model was qualitatively verified by comparing the experimental data of vitrinite reflectances and mineral geothermometers of the wall rocks with the simulation results. Furthermore, we modelled the hydrocarbon generation of the source rocks based on the simulated thermal history. In the region of about 100 m from the contacts, the organic matter was heated and partially transformed into hydrocarbon within only a few 1000 years, which was significantly faster than the normal burial generation process.     

Haynesville Shale Well Performance and Development Potential

Louisiana’s Haynesville Shale is one of several unconventional gas plays that have been discovered in the U.S. in recent years and promise to dramatically change the course of future domestic energy development. The Haynesville Shale is the deepest, hottest, and highest pressured shale among the big four plays in the U.S. with drilling and completion cost ranging between 7 and7 and 10 million per well. The average Haynesville well has an initial production rate of 10 MMcfd and declines rapidly, producing 80% of its expected recovery during the first 2 years of production. The purpose of this article is to describe the productivity characteristics of Haynesville wells, project future production from the inventory of active wells, and assess production potential based on drilling scenarios. We offer statistical analysis of the wells drilled to date and construct type profiles to characterize the play. We estimate that the current inventory of Haynesville wells will produce 3 Tcf over their lifecycles, and within the next 3 years, cumulative build-out in the region will range between 3 and 9 Tcf. To maintain current gas production levels in the state, we estimate that about 550 shale gas wells per year will need to be brought online over the next 3 years.     

Study of the Natural Gas Hydrate “Trap Zone” and the Methane Hydrate Potential in the Sverdrup Basin,Canada

The methane hydrate stability zone beneath Sverdrup Basin has developed to a depth of 2 km underneath the Canadian Arctic Islands and 1 km below sea level under the deepest part of the inter-island sea channels. It is not, however, a continuous zone. Methane hydrates are detected in this zone, but the gas hydrate/free gas contact occurs rarely. Interpretation of well logs indicate that methane hydrate occurs within the methane stability zone in 57 of 150 analyzed wells. Fourteen wells show the methane hydrate/free gas contact. Analysis of the distribution of methane hydrate and hydrate/gas contact occurrences with respect to the present methane hydrate stability zone indicate that, in most instances, the detected methane hydrate occurs well above the base of methane hydrate stability. This relationship suggests that these methane hydrates were formed in shallower strata than expected with respect to the present hydrate stability zone from methane gases which migrated upward into hydrate trap zones. Presently, only a small proportion of gas hydrate occurrences occur in close proximity to the base of predicted methane hydrate stability. The association of the majority of detected hydrates with deeply buried hydrocarbon discoveries, mostly conventional natural gas accumulations, or mapped seismic closures, some of which are dry, located in structures in western and central Sverdrup Basin, indicate the concurring relationship of hydrate occurrence with areas of high heat flow. Either present-day or paleo-high heat flows are relevant. Twenty-three hydrate occurrences coincide directly with underlying conventional hydrocarbon accumulations. Other gas hydrate occurrences are associated with structures filled with water with evidence of precursor hydrocarbons that were lost because of upward leakage.     

Deeply buried ancient volcanoes control hydrocarbon migration in the South China Sea

Seismic reflection data image now-buried and inactive volcanoes, both onshore and along the submarine portions of continental margins. However, the impact that these volcanoes have on later, post-eruption fluid flow events (e.g., hydrocarbon migration and accumulation) is poorly understood. Determining how buried volcanoes and their underlying plumbing systems influence subsurface fluid or gas flow, or form traps for hydrocarbon accumulations, is critical to de-risk hydrocarbon exploration and production. Here, we focus on evaluating how buried volcanoes affect the bulk permeability of hydrocarbon seals, and channel and focus hydrocarbons. We use high-resolution 3D seismic reflection and borehole data from the northern South China Sea to show how ca. <10 km wide, ca. <590 m high Miocene volcanoes, buried several kilometres (ca. 1.9 km) below the seabed and fed by a sub-volcanic plumbing system that exploited rift-related faults: (i) acted as long-lived migration pathways, and perhaps reservoirs, for hydrocarbons generated from even more deeply buried (ca. 8–10 km) source rocks; and (ii) instigated differential compaction and doming of the overburden during subsequent burial, producing extensional faults that breached regional seal rocks. Considering that volcanism and related deformation are both common on many magma-rich passive margins, the interplay between the magmatic products and hydrocarbon migration documented here may be more common than currently thought. Our results demonstrate that now-buried and inactive volcanoes can locally degrade hydrocarbon reservoir seals and control the migration of hydrocarbon-rich fluids and gas. These fluids and gases can migrate into and be stored in shallower reservoirs, where they may then represent geohazards to drilling and impact slope stability.